Method to hydraulically fracture a well

ABSTRACT

A system may include: a source of water fluidically coupled to a fracturing blender; water testing equipment disposed between the source of water and the fracturing blender wherein the water testing equipment is operable to measure at least one property of the source of water; a plurality of friction reducing polymers operable to be added to the fracturing blender; and a control system comprising: at least one processor; and a memory coupled to the processor to provide software that configures the processor to receive an input signal from the water testing equipment and select at least one of the plurality of friction reducing polymers.

BACKGROUND

Hydrocarbon-producing wells are often stimulated by hydraulic fracturingoperations, wherein proppants may be used to hold open or “prop” openfractures created during high-pressure pumping. Once the pumping-inducedpressure is removed, proppants may prop open fractures in the rockformation and thus preclude the fracture from closing. As a result, theamount of formation surface area exposed to the well bore may beincreased, enhancing hydrocarbon recovery rates.

An important component of hydraulic fracturing fluids is a frictionreducing polymer. Pumping rates for hydraulic fracturing operations mayregularly exceed 50 barrels per minute (8 m³/min) or more, which maycause turbulence in conduits such as wellbore tubing, liners, andcasings. Turbulent flow of hydraulic fracturing fluid decreases thepressure of the fluid as it flows through conduits leading to highhorsepower requirements to maintain pressure and flow rates. Some commonfriction reducing polymers may include long chain water soluble polymerswhich may aid in moderating turbulence by reducing eddy currents withina conduit.

A friction reducing polymer may be selected for a particular hydraulicfracturing fluid based at least in part on quality and properties ofwater available to create the hydraulic fracturing fluid at a well site.Oftentimes water is available from drilled water wells, surface watersuch as lakes and ponds, or seawater. Water from these and other sourcesmay contain dissolved solids such as salts and metals as well as otherchemical species. The friction reducing polymer may be significantlyaffected by the concentration of dissolved solids. In general, arelatively higher dissolved solids concentration may cause adverseeffects with hydration and stability of a given friction reducingpolymer as compared to a relatively lower dissolved solidsconcentration. The effects may be exacerbated at relatively higherconcentrations of dissolved solids to the point where the frictionreducing polymer is no longer performing to reduce turbulence within thehydraulic fracturing fluid.

There may be a wide variety of friction reducing polymers that may beincluded in hydraulic fracturing fluids for a particular use. Somefriction reducing polymers may be designed to operate within relativelyhigher total dissolved solids fluids for example. These severe dutyfriction reducing polymers may be relatively more expensive thanfriction reducing polymers that are not able to be used effectively inrelatively higher total dissolved solids fluids. The chosen frictionreducing polymer may be a factor of performance at a particular totaldissolved solids level and of the price of the friction reducingpolymer.

An operator or oilfield service company may design the hydraulicfracturing fluid based at least in part on tests performed on the waterat the well site. The water may be tested at least once before thehydraulic fracturing fluid is designed. A friction reducing polymer maythen be selected that would have the necessary performance with theproperties of the water as tested. However, there exist challenges whenthe water quality changes between fracturing stages or during aparticular fracturing stage. For example, if the total dissolved solidsincreases to a point where the selected friction reducing polymer isineffective, the hydraulic fracturing operation may not be able todeliver an effective pressure to the formation to fracture the formationand keep the fractures open to overcome the closing pressure of theformation. Alternatively, if the total dissolved solids decreases, theselected friction reducing polymer may not be the most cost effectivefriction reducing polymer to use.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of the present disclosure, andshould not be used to limit or define the disclosure.

FIG. 1 is a schematic view of an example well system utilized forhydraulic fracturing.

FIG. 2 is a schematic view of an example of a wellbore afterintroduction of fracturing fluid.

FIG. 3 illustrates a graph of total dissolved solids over time for awater source.

FIG. 4 illustrates a plot of total dissolved solids and of water samplestaken from a particular water region.

FIG. 5 illustrates a plot of total dissolved solids and of water samplestaken from a particular water region.

FIG. 6 illustrates results of a flow loop test for a friction reducingpolymer.

FIG. 7 illustrates results of a flow loop test for a set of frictionreducing polymers.

FIG. 8 illustrates results of a flow loop test for a friction reducingpolymer.

FIG. 9 illustrates a schematic of a hydraulic fracturing system.

DETAILED DESCRIPTION

The present disclosure may relate to subterranean operations, and, inone or more implementations, to hydraulic fracturing methods comprisingperforming real-time water quality analysis and correlating the waterquality analysis with archival data to determine a total dissolvedsolids concentration of the water. A friction reducing polymer and aconcentration thereof may be selected based on the total dissolvedsolids concentration to provide a fracturing fluid with a lower costwhile maintaining friction reducing properties. In an example, thefriction reducing polymer may be switched from a relatively higher costfriction reducing polymer to a relatively lower cost friction reducingpolymer when the total dissolved solids concentration changes fromrelatively higher to relatively lower.

A hydraulic fracturing fluid may include an aqueous base fluid, aproppant, and a friction reducing polymer. The aqueous based fluid mayinclude fresh water, produced water, salt water, surface water, or anyother suitable water. The term “salt water” is used herein to meanunsaturated salt solutions and saturated salt solutions including brinesand seawater. The aqueous base fluid may include dissolved species ofsalts and metals that make up the total dissolved solids count for aparticular sample of aqueous base fluid. Examples of dissolved speciesmay include, but are not limited to, lithium, sodium, potassium,beryllium, magnesium, calcium, strontium, iron, zing, manganese,molybdenum, sulfur in the form of hydrogen sulfide, other sulfides, andsulfates, arsenic, barium, boron, chromium, selenium, uranium, fluorine,chlorine, bromine, iodine, and combinations thereof. One of ordinaryskill in the art will understand that the present list of dissolvedspecies is not exhaustive of all possible species dissolved in aparticular sample of water. Furthermore, one of ordinary skill in theart will understand that particular dissolved species may be of concernwith regards to performance of a particular fiction reducing polymerthan other species. The water may be present in any amount by weightsuitable for a particular hydraulic fracturing application. For example,without limitation, the water may be present at a point ranging fromabout 50 wt. % to about 100 wt. % based on a total weight of thehydraulic fracturing fluid. Alternatively, at a point ranging from about50 wt. % to about 60 wt. %, at a point ranging from about 60 wt. % toabout 70 wt. %, at a point ranging from about 70 wt. % to about 80 wt.%, at a point ranging from about 80 wt. % to about 90 wt. %, or at apoint ranging from about 90 wt. % to about 100 wt. %. One of ordinaryskill in the art with the benefit of this disclosure should be able toselect an appropriate weight percent of water for a particular hydraulicfracturing fluid.

The hydraulic fracturing fluid may include a proppant. Proppants mayinclude a collection of solid particles that may be pumped into thesubterranean formation, such that the solid particles hold (or “prop”)open the fractures generated during a hydraulic fracturing treatment.The proppant may include a variety of solid particles, including, butnot limited to, sand, bauxite, ceramic materials, glass materials,polymer materials, polytetrafluoroethylene materials, nut shell pieces,cured resinous particulates including nut shell pieces, seed shellpieces, cured resinous particulates including seed shell pieces, fruitpit pieces, cured resinous particulates including fruit pit pieces,wood, composite particulates, and combinations thereof. Suitablecomposite particulates may include a binder and a filler materialwherein suitable filler materials include silica, alumina, fumed carbon,carbon black, graphite, mica, titanium dioxide, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, solid glass, and combinations thereof. The proppant mayhave any suitable particle size for a particular application such as,without limitation, nano particle size, micron particle size, or anycombinations thereof. As used herein, the term particle size refers to ad50 particle size distribution, wherein the d50 particle sizedistribution is the value of the particle diameter at 50% in thecumulative distribution. The d50 particle size distribution may bemeasured by particle size analyzers such as those manufactured byMalvern Instruments, Worcestershire, United Kingdom. As used herein,nano-size is understood to mean any proppant with a d50 particle sizedistribution of less than 1 micron. For example, a proppant with a d50particle size distribution at point ranging from about 10 nanometers toabout 1 micron. Alternatively, a proppant with a d50 particle sizedistribution at point ranging from about 10 nanometers to about 100nanometers, a proppant with a d50 particle size distribution at pointranging from about 100 nanometers to about 300 nanometers, a proppantwith a d50 particle size distribution at point ranging from about 300nanometers to about 700 nanometers, a proppant with a d50 particle sizedistribution at point ranging from about 700 nanometers to about 1micron, or a proppant with a d50 particle size distribution between anyof the previously recited ranges. As used herein, micron-size isunderstood to mean any proppant with a d50 particle size distribution ata point ranging from about 1 micron to about 1000 microns.Alternatively, a proppant with a d50 particle size distribution at pointranging from about 1 micron to about 100 microns, a proppant with a d50particle size distribution at point ranging from about 100 microns toabout 300 microns, a proppant with a d50 particle size distribution atpoint ranging from about 300 microns to about 700 micron, a proppantwith a d50 particle size distribution at point ranging from about 700microns to about 1000 microns, or a proppant with a d50 particle sizedistribution between any of the previously recited ranges.

Alternatively, proppant particle sizes may be expressed in U.S. meshsizes such as, for example, 20/40 mesh (212 μm-420 μm). Proppantsexpressed in U.S. mesh sizes may include proppants with particle sizesat a point ranging from about 8 mesh to about 140 mesh (106 μm-2.36 mm).Alternatively a point ranging from about 16-30 mesh (600 μm-1180 μm), apoint ranging from about 20-40 mesh (420 μm-840 μm), a point rangingfrom about 30-50 mesh (300 μm-600 μm), a point ranging from about 40-70mesh (212 μm-420 μm), a point ranging from about 70-140 mesh (106 μm-212μm), or alternatively any range there between. The standards andprocedures for measuring a particle size or particle size distributionmay be found in ISO 13503, or, alternatively in API RP 56, API RP 58,API RP 60, or any combinations thereof.

Proppants may include any suitable density. In some examples, proppantsmay have a density at a point ranging from about 1.25 g/cm³ to about 10g/cm³. Proppants may include any shape, including but not limited, tospherical, toroidal, amorphous, planar, cubic, or cylindrical. Proppantsmay further include any roundness and sphericity. Proppant may bepresent in the fracturing fluid in any concentration or loading. Withoutlimitation, the proppant may be present a point ranging from about 0.1pounds per gallon (“lb/gal”) (12 kg/m³) to about 14 lb/gal (1677 kg/m³).Alternatively, a point ranging from about 0.1 lb/gal (12 kg/m³) to about1 lb/gal (119.8 kg/m³), a point ranging from about 1 lb/gal (119.8kg/m³) to about 3 lb/gal (359.4 kg/m³), a point ranging from about 3lb/gal (359.4 kg/m³) to about 6 lb/gal (718.8 kg/m³), a point rangingfrom about 6 lb/gal (718.8 kg/m³) to about 9 lb/gal (1078.2 kg/m³), apoint ranging from about 9 lb/gal (1078.2 kg/m³) to about 12 lb/gal(1437.6 kg/m³), a point ranging from about 12 lb/gal (1437.6 kg/m³) toabout 14 lb/gal (1677.2 kg/m³), or alternatively, any rangetherebetween.

Friction reducing polymers may be included in the hydraulic fracturingfluid, for example, to form a slickwater fluid, for example. Thefriction reducing polymer may be a synthetic polymer. Additionally, forexample, the friction reducing polymer may be an anionic polymer or acationic polymer. By way of example, suitable synthetic polymers mayinclude any of a variety of monomeric units, including acrylamide,acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid,N,N-dimethylacrylamide, vinyl sulfonic acid, N-vinyl acetamide, N-vinylformamide, itaconic acid, methacrylic acid, acrylic acid esters,methacrylic acid esters and combinations thereof. Suitable frictionreducing polymers may be in an acid form or in a salt form. As will beappreciated by one of ordinary skill in the art, a variety of salts maybe prepared, for example, by neutralizing the acid form of the acrylicacid monomer or the 2-acrylamido-2-methylpropane sulfonic acid monomer.In addition, the acid form of the polymer may be neutralized by ionspresent in the fracturing fluid. The term “polymer” in the context of afriction reducing polymer, may be intended to refer to the acid form ofthe friction reducing polymer, as well as its various salts.

The friction reducing polymer may be included in the hydraulicfracturing fluid in the form of a liquid additive, for example, anamount ranging from about 0.1 gallons of the friction reducing polymerper thousand gallons of the fracturing fluid (“GPT”) to about 4 GPT.Alternatively, an amount ranging from about 0.1 GPT to about 0.5 GPT, anamount ranging from about 0.5 GPT to about 0.7 GPT, an amount rangingfrom about 0.7 GPT to about 1 GPT, an amount ranging from about 1 GPT toabout 1.3 GPT, an amount ranging from about 1.3 GPT to about 1.6 GPT, anamount ranging from about 1.6 GPT to about 2 GPT, an amount ranging fromabout 2 GPT to about 2.5 GPT, an amount ranging from about 2.5 GPT toabout 3 GPT, an amount ranging from about 3 GPT to about 3.5 GPT, anamount ranging from about 3.5 GPT to about 4 GPT, or alternatively, anamount ranging between any of the previously recited ranges. Whenprovided as a liquid additive, the friction reducing polymer may be inthe form of an emulsion, a liquid concentrate, or both. One of ordinaryskill will understand that a volume ratio such as GPT is equivalent to avolume ratio using a different basis such as liters or cubic meters.Additionally, the friction reducing polymer may be provided as a dryadditive and may be present in an amount ranging from about 0.01% wt. %to about 0.5 wt. % based on a total weight of the hydraulic fracturingfluid. Alternatively an amount ranging from about 0.01 wt. % to about0.025 wt. %, an amount ranging from about 0.025 wt. % to about to about0.04 wt. %, an amount ranging from about 0.04 wt. % to about 0.06 wt. %,an amount ranging from about 0.06 wt. % to about 0.09 wt. %, an amountranging from about 0.09 wt. % to about 0.12 wt. %, an amount rangingfrom about 0.12 wt. % to about 0.15 wt. %, an amount ranging from about0.15 wt. % to about 0.2 wt. %, an amount ranging from about 0.2 wt. % toabout 0.25 wt. %, an amount ranging from about 0.25 wt. % to about 0.3wt. %, an amount ranging from about 0.3 wt. % to about 0.35 wt. %, anamount ranging from about 0.35 wt. % to about 0.4 wt. %, an amountranging from about 0.45 wt. % to about 0.5 wt. %, or alternatively, anamount ranging between any of the previously recited ranges.

Gelling agents may be included in the hydraulic fracturing fluid toincrease the hydraulic fracturing fluid's viscosity which may be desiredfor some types of subterranean applications. For example, an increase inviscosity may be used for transferring hydraulic pressure to diverttreatment fluids to another part of a formation or for preventingundesired leak-off of fluids into a formation from the buildup of filtercakes. The increased viscosity of the gelled or gelled and cross-linkedtreatment fluid, among other things, may reduce fluid loss and may allowthe fracturing fluid to transport significant quantities of suspendedproppant. Gelling agents may include, but are not limited to, anysuitable hydratable polymer, including, but not limited to,galactomannan gums, cellulose derivatives, combinations thereof,derivatives thereof, and the like. Galactomannan gums are generallycharacterized as having a linear mannan backbone with various amounts ofgalactose units attached thereto. Examples of suitable galactomannangums include, but are not limited to, gum arabic, gum ghatti, gumkaraya, tamarind gum, tragacanth gum, guar gum, locust bean gum,combinations thereof, derivatives thereof, and the like. Other suitablegums include, but are not limited to, hydroxyethylguar,hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar andcarboxymethylhydroxypropylguar. Examples of suitable cellulosederivatives include hydroxyethyl cellulose, carboxyethylcellulose,carboxymethylcellulose, and carboxymethylhydroxyethylcellulose;derivatives thereof, and combinations thereof. The crosslinkablepolymers included in the treatment fluids of the present disclosure maybe naturally-occurring, synthetic, or a combination thereof. Thecrosslinkable polymers may include hydratable polymers that contain oneor more functional groups such as hydroxyl, cis-hydroxyl, carboxyl,sulfate, sulfonate, phosphate, phosphonate, amino, or amide groups. Incertain systems and/or methods, the crosslinkable polymers may be atleast partially crosslinked, wherein at least a portion of the moleculesof the crosslinkable polymers are crosslinked by a reaction including acrosslinking agent. The gelling agent may be present in the fracturingfluid in an amount ranging from about 5 lbs/1,000 gal of hydraulicfracturing fluid (0.5991 kg/m{circumflex over ( )}3) to about 20lbs/1,000 gal (2.3946 kg/m{circumflex over ( )}3). Alternatively, in anamount ranging from about 5 lbs/1,000 gal (0.5991 kg/m{circumflex over( )}3) to about 10 lbs/1,000 gal (1.198 kg/m{circumflex over ( )}3), inan amount ranging from about 10 lbs/1,000 gal (1.198 kg/m{circumflexover ( )}3) to about 15 lb/1,000 gal (1.797 kg/m{circumflex over ( )}3),in an amount ranging from about 15 lb/1,000 gal (1.797 kg/m{circumflexover ( )}3) to about 20 lb/1,000 gal (2.3946 kg/m{circumflex over( )}3), or alternatively, an amount ranging between any of thepreviously recited ranges.

The hydraulic fracturing fluid may include any number of additionaloptional additives, including, but not limited to, salts, acids, fluidloss control additives, gas, foamers, corrosion inhibitors, scaleinhibitors, catalysts, clay control agents, biocides, friction reducingpolymers, iron control agent, antifoam agents, bridging agents,dispersants, hydrogen sulfide (“H₂S”) scavengers, carbon dioxide (“CO₂”)scavengers, oxygen scavengers, lubricants, viscosifiers, breakers,weighting agents, inert solids, emulsifiers, emulsion thinner, emulsionthickener, surfactants, lost circulation additives, pH control additive,buffers, crosslinkers, stabilizers, chelating agents, mutual solvent,oxidizers, reducers, consolidating agent, complexing agent, particulatematerials and any combination thereof. With the benefit of thisdisclosure, one of ordinary skill in the art should be able to recognizeand select a suitable optional additive for use in the fracturing fluid.

FIG. 1 illustrates an example of a well system 104 that may be used tointroduce proppant 116 into fractures 100. Well system 104 may include afluid handling system 106, which may include fluid supply 108, mixingequipment 109, pumping equipment 110, and wellbore supply conduit 112.Pumping equipment 110 may be fluidly coupled with the fluid supply 108and wellbore supply conduit 112 to communicate a fracturing fluid 117,which may include proppant 116 into wellbore 114. Proppant 116 may beany of the proppants described herein. The fluid supply 108 and pumpingequipment 110 may be above the surface 118 while the wellbore 114 isbelow the surface 118.

Well system 104 may also be used for the pumping of a pad or pre-padfluid into the subterranean formation at a pumping rate and pressure ator above the fracture gradient of the subterranean formation to createand maintain at least one fracture 100 in subterranean formation 120.The pad or pre-pad fluid may be substantially free of solid particlessuch as proppant, for example, less than 1 wt. % by weight of the pad orpre-pad fluid. Well system 104 may then pump the fracturing fluid 117into subterranean formation 120 surrounding the wellbore 114. Generally,a wellbore 114 may include horizontal, vertical, slanted, curved, andother types of wellbore geometries and orientations, and the proppant116 may generally be applied to subterranean formation 120 surroundingany portion of wellbore 114, including fractures 100. The wellbore 114may include the casing 102 that may be cemented (or otherwise secured)to the wall of the wellbore 114 by cement sheath 122. Perforations 123may allow communication between the wellbore 114 and the subterraneanformation 120. As illustrated, perforations 123 may penetrate casing 102and cement sheath 122 allowing communication between interior of casing102 and fractures 100. A plug 124, which may be any type of plug foroilfield applications (e.g., bridge plug), may be disposed in wellbore114 below the perforations 123.

In accordance with systems and/or methods of the present disclosure, aperforated interval of interest 130 (depth interval of wellbore 114including perforations 123) may be isolated with plug 124. A pad orpre-pad fluid may be pumped into the subterranean formation 120 at apumping rate and pressure at or above the fracture gradient to createand maintain at least one fracture 100 in subterranean formation 120.Then, proppant 116 may be mixed with an aqueous based fluid via mixingequipment 109, thereby forming a fracturing fluid 117, and then may bepumped via pumping equipment 110 from fluid supply 108 down the interiorof casing 102 and into subterranean formation 120 at or above a fracturegradient of the subterranean formation 120. Pumping the fracturing fluid117 at or above the fracture gradient of the subterranean formation 120may create (or enhance) at least one fracture (e.g., fractures 100)extending from the perforations 123 into the subterranean formation 120.Alternatively, the fracturing fluid 117 may be pumped down productiontubing, coiled tubing, or a combination of coiled tubing and annulusbetween the coiled tubing and the casing 102.

At least a portion of the fracturing fluid 117 may enter the fractures100 of subterranean formation 120 surrounding wellbore 114 by way ofperforations 123. Perforations 123 may extend from the interior ofcasing 102, through cement sheath 122, and into subterranean formation120.

Referring to FIG. 2, the wellbore 114 is shown after placement of theproppant 116 in accordance with systems and/or methods of the presentdisclosure. Proppant 116 may be positioned within fractures 100, therebypropping open fractures 100.

The pumping equipment 110 may include a high pressure pump. As usedherein, the term “high pressure pump” refers to a pump that is capableof delivering the fracturing fluid 117 and/or pad/pre-pad fluid downholeat a pressure of about 1000 psi (6894 kPa) or greater. A high pressurepump may be used when it is desired to introduce the fracturing fluid117 and/or pad/pre-pad fluid into subterranean formation 120 at or abovea fracture gradient of the subterranean formation 120, but it may alsobe used in cases where fracturing is not desired. Additionally, the highpressure pump may be capable of fluidly conveying particulate matter,such as the proppant 116, into the subterranean formation 120. Suitablehigh pressure pumps may include, but are not limited to, floating pistonpumps and positive displacement pumps. Without limitation, the initialpumping rates of the pad fluid, pre-pad fluid and/or fracturing fluid117 may range from about 15 barrels per minute (“bbl/min”) (2385 l/min)to about 80 bbl/min (12719 l/min), enough to effectively create afracture into the formation and place the proppant 116 into at least onefracture 101.

Alternatively, the pumping equipment 110 may include a low pressurepump. As used herein, the term “low pressure pump” refers to a pump thatoperates at a pressure of about 1000 psi (6894 kPa) or less. A lowpressure pump may be fluidly coupled to a high pressure pump that may befluidly coupled to a tubular (e.g., wellbore supply conduit 112). Thelow pressure pump may be configured to convey the fracturing fluid 117and/or pad/pre-pad fluid to the high pressure pump. The low pressurepump may “step up” the pressure of the fracturing fluid 117 and/orpad/pre-pad fluid before it reaches the high pressure pump.

Mixing equipment 109 may include a mixing tank that is upstream of thepumping equipment 110 and in which the fracturing fluid 117 may beformulated. The pumping equipment 110 (e.g., a low pressure pump, a highpressure pump, or a combination thereof) may convey fracturing fluid 117from the mixing equipment 109 or other source of the fracturing fluid117 to the casing 102. Alternatively, the fracturing fluid 117 may beformulated offsite and transported to a worksite, in which case thefracturing fluid 117 may be introduced to the casing 102 via the pumpingequipment 110 directly from its shipping container (e.g., a truck, arailcar, a barge, or the like) or from a transport pipeline. In eithercase, the fracturing fluid 117 may be drawn into the pumping equipment110, elevated to an appropriate pressure, and then introduced into thecasing 102 for delivery downhole.

A hydraulic fracturing operation may operate in stages where a bridgeplug, frac plug, or other obstruction is inserted into the wellbore toprevent fluid communication with a region of the wellbore after thebridge plug. A perforating gun including explosive shaped charges may beinserted into a region of the wellbore before the bridge plug (i.e. aregion where the measured depth is less than the measured depth of thebridge plug) and perforate holes through the walls of the wellbore. Theperforating gun may be removed from the wellbore and a fracturing fluidintroduced thereafter. The stage is completed when the planned volume offluid and proppant has been introduced into the subterranean formation.Another stage may begin with the insertion of a second bridge plug intoa wellbore region before the bridge plug.

As previously mentioned, a total dissolved solids concentration may varybetween fracturing stages or vary within a stage. The performance of afriction reducing polymer in a hydraulic fracturing fluid may beadversely affected by the total dissolved solids content of the aqueousbase fluid used to make the hydraulic fracturing fluid. In particular,multivalent cations such as calcium, iron, magnesium, and single valentcations such as sodium and potassium may prevent friction reducingpolymer from fully hydrating and prevent the friction reducing polymerfrom performing well in the hydraulic fracturing fluid. There may existfriction reducing polymers that are able to overcome the adverse effectsof single valent and multivalent, however, such friction reducingpolymers may be costly. A total dissolved solids (TDS) measurement mayprovide an estimate of the concentration of single valent andmultivalent in the aqueous base fluid which may allow a user to select afriction reducing polymer that will perform at a particular TDS level.

FIG. 3 illustrates an example of a water source wherein the TDSconcentration over a period of 12 days was monitored. The TDSconcentration was found to vary between about 150,000 parts per million(ppm) at a high and 40,000 ppm at a low. As one of ordinary skill in theart will appreciate, a hydraulic fracturing operation may requiremultiple days or weeks to complete depending on the number of stages aparticular well will require and the number of wells on a particular padsite being fractured. If a single laboratory test was performed todetermine the TDS and a hydraulic fracturing fluid was prepared with aselected friction reducing polymer based on the measured TDS, thefriction reducing polymer may not perform satisfactory over the entiretime period of fracturing.

Some friction reducing polymer may be available for different TDSlevels, for example, <20 k TDS, 0-70 k TDS, 0-120 k TDS, 40-200 k TDS,and 150-350 k TDS. Measurements of TDS may have units of parts permillion (ppm), for example. 1 ppm is equivalent to 1 milligram ofdissolved solids per kilogram of water. However, there may be fewfriction reducing polymer available that are economical that will coverthe entire range of TDS. Furthermore, each specific friction reducingpolymer has a particular operating band where the friction reducingpolymer performs best. In general, friction reducing polymers that aredesigned to operate in relatively higher TDS environments are moreexpensive per unit volume than a friction reducing polymer that isdesigned to operate in a relatively lower TDS environment. When the TDSlevel approaches the upper limit for a particular friction reducingpolymer, a concentration of the particular friction reducing polymer mayneed to be increased to compensate for the loss of friction reductionability. The increased concentration of friction reducing polymer maycause an increase in operating costs and have other adverse effects onother chemical species of the hydraulic fracturing fluid. Similarly, ifa TDS level drops below an operating range where the friction reducingpolymer is designed to operate, there may be additional operationalcosts to using the relatively more expensive friction reducing polymerwhen a relatively cheaper friction reducing polymer is available thatwould perform adequately at the lower TDS level.

One important factor in selecting the type of friction reducing polymermay be the pressure response at the wellhead. A pressure transducercoupled to the wellhead, headers, risers, or other equipment fluidicallycoupled to the wellbore may allow a pressure at the surface to bemonitored. If a friction reducing polymer becomes ineffective due a TDSlevel of the water source changing, a resultant pressure increase may beobserved at the pressure transducer due to the friction reducing polymerbeing unable to reduce fluid friction at a higher TDS concentration. Thewellhead pressure response may provide a measurement of theeffectiveness of the friction reducing polymer at reducing friction in aconduit. Performance of a friction reducing polymer may also bemonitored in a flow loop where a fluid including the friction reducingpolymer is circulated continuously in a loop, passing through ameasurement section. Pressure response of the fluid may be measured inthe measurement section as the composition of the fluid is varied. Aflow loop may provide a method to test friction reducing polymers whilevarying TDS concentration. The example section of the present disclosureillustrates some results of testing various friction reducing polymersin a flow loop.

Laboratory testing may be performed on friction reducing polymers todetermine the operational limits of each friction reducing polymer. Afluid including a friction reducing polymer may be subjected to apressure response test in a flow loop for example or other suitablelaboratory methods to determine a percent reduction in pressure losswhile varying one or more concentrations of ions in the fluid. Thespecific ion of interest, such as calcium for example, may be variedfrom zero up to a point where the friction reducing polymer has reducedperformance. Reduction in performance may be observed as a decrease inpressure reduced (i.e. the pressure increases) over a period of time.For example, a particular friction reducing polymer may reduce pressureby 70% with zero cation concentration but at 40,000 PPM calcium, mayonly reduce pressure by 40% and then decrease to zero percent reductionover a period of time. The friction reducing polymer may be tested withother ions such as iron to generate a complete operational limit of thefriction reducing polymer. The data relating to the operational limitsof each friction reducing polymer may be stored in an operationaldatabase, for example. In some examples, the operational database may bea historical database as will be described in detail below.

A method is described that allows for one of ordinary skill in the artto dynamically select an appropriate friction reducing polymer for aparticular TDS level to reduce operational costs associated withhydraulic fracturing operations. The methods described herein maygenerally couple laboratory testing techniques to obtain real-time waterquality analyses with archival data on both water analyses acrosshistorical fracturing jobs and laboratory testing data of frictionreducing polymers. The laboratory testing techniques may determine oneor more properties that may be correlated to determine TDSconcentration. Some laboratory testing techniques may include, but arenot limited to, conductivity measurement, density measurement, and flowloop measurement. The laboratory testing techniques do not necessarilyhave to be performed in a laboratory. The testing techniques may also beperformed any time before the fracturing fluid is made. For example, thetesting techniques may be performed in line with a water source used formaking the hydraulic fracturing fluid. The testing may be performed bypositioning testing equipment such as a conductivity probe, adensometer, flow loop or combination thereof before a blender tub wherethe fracturing fluid is blended. The testing equipment may be placed,without limitation, on a fluid header, a fluid tank, in line with ahose, in an inlet to a blender tub, or in any position before theblender tub. Spectrographic techniques may also be used to determine ionconcentrations.

Conductivity measurements may be made using a conductivity probe ormulti meter. The conductivity probe may be of any type, for example,potentiometric type or inductive type. As one of ordinary skill in theart will appreciate, dissolved ionized solids such as salts and mineralsincrease the electrical conductivity measurement of a solution.Measuring conductivity may yield an indirect measurement of TDS. Aspreviously discussed, the TDS measurement may be correlated to an ionconcentration using a historical database.

Density measurements may be made using any kind of densometer. Forexample, gravitic density meters, Coriolis density meters, nucleardensity meters, microwave density meters, ultrasonic density meters, orany combination thereof. Alternatively, density may be calculated usingrefractive index measurements. As one of ordinary skill in the art willappreciate, a density of a solution will increase with increasingconcentration of dissolved solids. Measuring density of a solution mayyield an indirect measurement of TDS which may then be correlated to anion concentration using a historical database.

FIG. 4 illustrates a plot of TDS and density for about 1000 watersamples taken from a particular water region. There is a strongcorrelation between density and TDS for the particular samples. Giventhe strong correlation between density and TDS, a TDS estimate may bemade for a sample of water taken from the particular region by measuringthe density of the sample. With reference to FIG. 5, another example ofa dissolved solids and density plot is illustrated, wherein thedissolved solids is a count of the total cations in the sample. There isa strong correlation between concentration of cations and density. Giventhe strong correlation between density and dissolved cationconcentration, a dissolved cation concentration estimate may be made fora sample of water taken from the particular region by measuring thedensity of the sample. The plots from FIGS. 4 and 5 may be consideredpart of a historical database as the data from FIGS. 4 and 5 may becollected over a period of time. The data points may indicate themaximum ion concentrations observed from the particular water regionover a period of time as well. For example, with reference to FIG. 5, ifa particular sample has a density of about 1 g/cm³, the expected cationconcentration would be approximately 22,000-30,000 ppm. A frictionreducing polymer that is operable up to 30,000 ppm may be selected toblend a fracturing fluid if a measured density of the water is about 1g/cm³ and the water used to blend the fracturing fluid is from theparticular region used to generate the data of FIG. 5.

A historical database for a particular source of water may beconstructed by monitoring the TDS concentration of the source of waterand measuring density and ion levels therein. A historical database mayallow correlations to be made to predict the concentration of ions in asample of water from the source of water. In particular, a density orconductivity measurement may be used to determine the TDS level whichmay then be correlated to calcium and iron concentration in a sample ofwater. The historical database may also contain the identities andconcentrations of the species of ions at the particular measured TDSlevel.

A method may include using a conductivity probe to determine the TDSlevel of a water source before entering a blender unit for blending ahydraulic fracturing fluid. As previously discussed, the conductivityprobe may be placed anywhere before the water enters the blender tub forexample. The TDS level may then be correlated using the historicaldatabase to a highest concentration of calcium and iron at the TDSlevel. An operational database including operational limits of frictionreducing polymers may be referenced to determine which friction reducingpolymers that will perform adequately at the highest concentration ofcalcium and iron. A friction reducing polymer may then be selected basedat least in part on the determination of which friction reducingpolymers will perform adequately. The selected friction reducing polymermay then be used in the blending of the hydraulic fracturing fluid.

A method may include using a densometer to determine the density of awater source before entering a blender unit for blending a hydraulicfracturing fluid. As previously discussed, the densometer may be placedanywhere before the water enters the blender tub for example. Thedensity may then be correlated using the historical database to ahighest concentration of calcium and iron at the density level. Anoperational database including operational limits of friction reducingpolymers may be referenced to determine which friction reducing polymersthat will perform adequately at the highest concentration of calcium andiron. A friction reducing polymer may then be selected based at least inpart on the determination of which friction reducing polymers willperform adequately. The selected friction reducing polymer may then beused in the blending of the hydraulic fracturing fluid.

A method may include using a flow loop to determine a friction reducingpolymer performance with a water source before entering a blender unitfor blending a hydraulic fracturing fluid. The TDS level may bedetermined by any of the previously mentioned methods. The historicaldatabase and operational database may then be referenced to determinefriction reducing polymer performance for various friction reducingpolymer produces at the TDS level measured. A friction reducing polymermay then be selected based at least in part on the determination ofwhich friction reducing polymers will perform adequately. The selectedfriction reducing polymer may then be used in the blending of thehydraulic fracturing fluid.

A method may include using a conductivity probe to determine the TDSlevel of a water source before entering a blender unit for blending ahydraulic fracturing fluid. As previously discussed, the conductivityprobe may be placed anywhere before the water enters the blender tub forexample. The TDS level may then be correlated using the historicaldatabase to a highest concentration of calcium and iron at the TDSlevel. An operational database including operational limits of frictionreducing polymers may be referenced to determine which friction reducingpolymers that will perform adequately at the highest concentration ofcalcium and iron. A friction reducing polymer may then be selected basedat least in part on the determination of which friction reducingpolymers will perform adequately. The selected friction reducing polymermay then be used blended to a fracturing fluid and tested in a flow loopfor performance. If the performance of the friction reducing polymer isadequate the friction reducing polymer may be used to blend a hydraulicfracturing fluid.

A method may include using a densometer to determine the density of awater source before entering a blender unit for blending a hydraulicfracturing fluid. As previously discussed, the densometer may be placedanywhere before the water enters the blender tub for example. Thedensity may then be correlated using the historical database to ahighest concentration of calcium and iron at the density level. Anoperational database including operational limits of friction reducingpolymers may be referenced to determine which friction reducing polymersthat will perform adequately at the highest concentration of calcium andiron. A friction reducing polymer may then be selected based at least inpart on the determination of which friction reducing polymers willperform adequately. The selected friction reducing polymer may then beused blended to a fracturing fluid and tested in a flow loop forperformance. If the performance of the friction reducing polymer isadequate the friction reducing polymer may be used to blend a hydraulicfracturing fluid.

A method may include using a densometer to determine the density orconductivity meter to determine conductivity. As previously discussed,density and conductivity may be correlated to TDS levels. Equilibriumequations may then be used to determine calcium and iron levels for TDSat different densities and conductivities. An operational databaseincluding operational limits of friction reducing polymers may bereferenced to determine which friction reducing polymers that willperform adequately at the calculated concentration of calcium and iron.A friction reducing polymer may then be selected based at least in parton the determination of which friction reducing polymers will performadequately. As used herein, perform adequately means that in alaboratory test, such as a flow loop test, the friction reducer will notlose more than 15% friction reduction ability for a period of 15minutes. The selected friction reducing polymer may then be used toblend a fracturing fluid which may then be tested in a flow loop forperformance. If the performance of the friction reducing polymer isadequate the friction reducing polymer may be used to blend a hydraulicfracturing fluid for pumping into a subterranean formation.

FIG. 9 illustrates a system 900 using the methods described herein. Asource of water 905 may be fluidically coupled to a hydraulic fracturingblender 910. Source of water 905 may be any source of water describedherein including, but not limited to, a tank, a water header, a waterwell, or a surface body of water such as a lake, stream, pond, andocean, or the like. Hydraulic fracturing blender 910 may include allequipment required to prepare a hydraulic fracturing fluid, including,but not limited to, a blender tub, proppant addition equipment such assand screws, centrifugal pumps, liquid additive pumps, and otherequipment well known in the art. Water testing equipment 915 may beplaced in line between source of water 905 and hydraulic fracturingblender 910. Water testing equipment 915 may be any of the equipmentpreviously mentioned including a densometer, a conductivity meter, aspectrometer, a flow loop, or any combinations thereof. Water testingequipment 915 may be electrically coupled to control system 920 whichmay be operable to control hydraulic fracturing blender 910. Watertesting equipment 915 may send an output signal to control system 920which may provide information about density, conductivity,spectrographic output, or flow characteristics such as pressure responseto control system 920.

Control system 920 may include a computer system capable of interactingwith and controlling valves, motors, pumps, and other equipment inhydraulic fracturing blender 910. The computer system may includesoftware capable of controlling equipment in hydraulic fracturingblender 910 in the form of a computer program on a non-transitorycomputer readable media, such as a CD, a DVD, a USB drive, a portablehard drive, ROM, RAM, or other portable memory. A processor may read thesoftware from the computer readable media through an input/output deviceand store the software in memory where it is prepared for executionthrough compiling and linking, if necessary, and then executed. In oneexample, control system 920 may accepts input through an input/outputdevice such as a keyboard or keypad, mouse, touchpad, touch screen,etc., and provides outputs through an input/output device such as amonitor or printer. Control system 920 may also accept inputs and sendoutputs to and from hydraulic fracturing blender 910 and water testingequipment 915.

The software of control system 920 may include a historical database andoperational database as previously described. In some examples thehistorical database and operational database may the same database.Control system 920 may receive an input signal from water testingequipment 915 which the software may then use to correlate to a TDSconcentration using, for example, a calibration curve. The software mayfurther correlate the TDS to an ion concentration using the historicaldatabase as previously discussed. The software may reference theoperational database to determine which friction reducing polymersperform adequately at the ion concentration and select a frictionreducing polymer to blend with a hydraulic fracturing fluid.

FIG. 9 illustrates a first friction reducing polymer source 925, asecond friction reducing source 926, and a third friction reducingsource 927. Each friction reducing polymer source may be provided as atank, chemical tote, chemical barrel, dry additive, or by any othermeans. Each friction reducing polymer source may be fluidically coupledor otherwise operable to be added to the blender tub of hydraulicfracturing blender 910. The friction reducing polymer source may befluidically coupled to the blender tub by a liquid additive pump forexample. Although only three friction reducing polymer sources areillustrated in FIG. 9, any number of friction reducing polymer sourcesmay be used. Control system 920 may determine an ion concentration aspreviously described and select a friction reducing polymer from firstfriction reducing polymer source 925, second friction reducing source926, third friction reducing source 927 or a combination thereof to addto the blender tub based at least in part on the ion concentration andperformance characteristics of each friction reducing polymer at theparticular ion concentration.

During a hydraulic fracturing stage, hydraulic fracturing blender 910may blend a hydraulic fracturing fluid including the source of water 905and friction reduction agent selected based at least in part on the ionconcentration and discharge the hydraulic fracturing fluid to pump 930.Pump 930 may be a high pressure pump, for example, a pump capable ofpressurizing the hydraulic fracturing fluid to about 10,000 psi orgreater. Pump 930 may be capable of generating a pressure above afracture gradient of a formation penetrated by wellbore 935. Pump 930may pressurize the hydraulic fracturing fluid above the fracturegradient of the formation and discharge the hydraulic fracturing fluidinto wellbore 935.

As previously described, a TDS concentration of the source of water 905may vary with time such as between hydraulic fracturing stages or duringa hydraulic fracturing stage and a change in TDS concentration maynegatively affect a pressure response performance of a friction reducingpolymer in a hydraulic fracturing fluid. The system 900 may be able todynamically compensate for the changes in TDS concentration between orduring a hydraulic fracturing stage. Water testing equipment 915 maycontinuously or discretely measure a property of the source of water 905and send a signal to control system 920. Control system 920 maycontinually reference the historical database to determine if an ionconcentration of the source of water is within the operable range of thefriction reducing polymer being added to the blender tub. If the controlsystem 920 determines that the ion concentration is outside of theoperable range, the control system 920 may stop adding the frictionreducing polymer that is outside the operable range and switch toanother friction reducing polymer that is within the operable range.Alternatively, switching friction reducing polymers may be performedmanually by an operator.

Accordingly, the present disclosure may be practiced according to one ormore of the following statements.

Statement 1. A method comprising: correlating a total dissolved solids(TDS) concentration of a water source to an ion concentration; andselecting at least one friction reducing polymer for a hydraulicfracturing operation based at least in part on the ion concentration.

Statement 2. The method of statement 1 further comprising measuring aproperty of the water source wherein the measured property is density,conductivity, reflected ration, emitted radiation, or a combinationthereof.

Statement 3. The method of any of statements 1-2 wherein the step ofcorrelating comprises correlating the TDS concentration using ahistorical database, the historical database comprising a trend of TDSconcentration to ion concentration.

Statement 4. The method of any of statements 1-3 wherein the ionconcentration is a concentration of at least one Group(I) ion, at leastone Group(II) ion, at least one metal ion, or a combination thereof.

Statement 5. The method of any of statements 1-4 wherein the step ofselecting at least one friction reducing polymer comprises using ahistorical database and correlating the ion concentration to frictionreducing polymers that reduce friction at the ion concentration.

Statement 6. The method of any of statements 1-5 further comprisingadding the selected at least one friction reducing polymer to ahydraulic fracturing fluid comprising water from the water source.

Statement 7. The method of any of statements 1-6 further comprisingmeasuring a conductivity of the water source to determine the TDSconcentration, wherein the step of correlating comprises correlating theTDS concentration using a historical database, the historical databasecomprising a trend of TDS concentration to ion concentration, andwherein the method further comprises adding the selected at least onefriction reducing polymer to a hydraulic fracturing fluid comprisingwater from the water source.

Statement 8. The method of any of statements 1-7 wherein the selectingat least one friction reducing polymer is automatic.

Statement 9. The method of any of statements 1-8 wherein the selectingat least one friction reducing polymer is manually done by a user.

Statement 10. A method comprising: measuring at least one property of awater source to determine a total dissolved solids (TDS) concentration;correlating the TDS concentration to an ion concentration; selecting atleast one friction reducing polymer based at least in part on the ionconcentration; and introducing the at least one friction reducingpolymer and water from the water source into a flow loop.

Statement 11. The method of statement 10 wherein the measured propertyis density, conductivity, reflected ration, emitted radiation, or acombination thereof.

Statement 12. The method of any of statements 10-11 wherein the step ofcorrelating comprises correlating the property using a historicaldatabase, the historical database comprising a trend of TDSconcentration to ion concentration.

Statement 13. The method of any of statements 10-12 wherein the step ofselecting at least one friction reducing polymer comprises using ahistorical database and correlating the ion concentration to frictionreducing polymers that reduce friction at the ion concentration.

Statement 14. The method of any of statements 10-13 further comprisingadding the selected at least one friction reducing polymer to ahydraulic fracturing fluid comprising water from the water source.

Statement 15. A system comprising: a source of water fluidically coupledto a fracturing blender; water testing equipment disposed between thesource of water and the fracturing blender wherein the water testingequipment is operable to measure at least one property of the source ofwater; a plurality of friction reducing polymers operable to be added tothe fracturing blender; and a control system comprising: at least oneprocessor; and a memory coupled to the processor to provide softwarethat configures the processor to receive an input signal from the watertesting equipment, access a historical database, use the historicaldatabase to correlate the property to a concentration of at least oneGroup(I) ion, at least one Group(II) ion, at least one metal ion, or acombination thereof, select at least one of the plurality of frictionreducing polymers based at least in part on the concentration of atleast one Group(I) ion, at least one Group(II) ion, at least one metalion, or a combination thereof, and send an output signal to thefracturing blender to add the at least one of the plurality of frictionreducing polymers to the fracturing blender.

Statement 16. The system of statement 15 wherein the water testingequipment is a densometer, a conductivity meter, a flow loop, aspectroscope, or a combination thereof.

Statement 17. The system of any of statements 15-16 wherein the frictionreducing polymers are provided as a liquid, a powder, or a combinationthereof.

Statement 18. The system of any of statements 15-17 wherein thehistorical database comprises a trend of TDS concentration to ionconcentration.

Statement 19. The system of any of statements 15-18 wherein the step ofselecting at least one friction reducing polymer comprises using ahistorical database and correlating the ion concentration to frictionreducing polymers that reduce friction at the ion concentration.

Statement 20. The system of any of statements 15-19 wherein the frictionreducing polymer selected will not lose more than 15% friction reductionability for a period of 15 minutes at the ion concentration.

EXAMPLES

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the invention.

Example 1

A friction reducing flow loop test was performed to determine theperformance of a friction reducing polymer over time. FIG. 6 illustratesthe results of the experiment. The friction reducing polymer was Legend™LD-2600 Anionic Liquid Friction Reducer available from HalliburtonEnergy Services at 0.5 gallons per thousand gallons (GPT) concentration.It was observed that the friction reducing polymer was ineffective atreducing friction for about 1 minute until the friction reducing polymerwas fully hydrated. It was then observed that the friction was reducedby approximately 75% for a period of about 26 minutes before the testwas terminated.

Example 2

A friction reducing flow loop test was performed on Legend™ LD-2600Anionic Liquid Friction Reducer at 0.5, 0.75, and 1.0 GPT concentrationsto determine the relative performance the friction reducing polymerconcentrations over time. FIG. 7 illustrates the results of theexperiment. It was observed that at each concentration, the frictionreducing polymer was ineffective at reducing friction for about 1 minuteuntil the friction reducing polymer was fully hydrated. It was thenobserved that the friction was reduced by approximately 70% for eachconcentration for a period of about 26 minutes before the test wasterminated.

Example 3

A friction reducing flow loop test was performed with Legend™ LD-2600Anionic Liquid Friction Reducer at 0 1.0 GPT concentration to determinethe performance of with a TDS concentration above the friction reducingpolymer's operable range. FIG. 8 illustrates the results of theexperiment. It was observed that the friction reducing polymer increasedthe observed friction for a period of about 2.5 minutes beforedecreasing observed friction to approximately 49% at 4 minutes. Thefriction reducing polymer became less effective at reducing frictionbetween 4 minutes until 26 minutes from reducing 49% friction toreducing 10% friction.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent embodiments may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, all combinations of each embodiment are contemplated andcovered by the disclosure. Furthermore, no limitations are intended tothe details of construction or design herein shown, other than asdescribed in the claims below. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee. It is therefore evident that the particularillustrative embodiments disclosed above may be altered or modified andall such variations are considered within the scope and spirit of thepresent disclosure. If there is any conflict in the usages of a word orterm in this specification and one or more patent(s) or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

What is claimed is:
 1. A system comprising: a source of waterfluidically coupled to a fracturing blender; water testing equipmentdisposed between the source of water and the fracturing blender whereinthe water testing equipment is operable to measure at least one propertyof the source of water; a plurality of friction reducing polymersoperable to be added to the fracturing blender; and a control systemcomprising: at least one processor; and a memory coupled to theprocessor to provide software that configures the processor to receivean input signal from the water testing equipment, access a historicaldatabase, use the historical database to correlate the property to aconcentration of at least one Group(I) ion, at least one Group(II) ion,at least one metal ion, or a combination thereof, select at least one ofthe plurality of friction reducing polymers based at least in part onthe concentration of at least one Group(I) ion, at least one Group(II)ion, at least one metal ion, or a combination thereof, and send anoutput signal to the fracturing blender to add the at least one of theplurality of friction reducing polymers to the fracturing blender. 2.The system of claim 1 wherein the water testing equipment is adensometer, a conductivity meter, a flow loop, a spectroscope, or acombination thereof.
 3. The system of claim 1 wherein the frictionreducing polymers are provided as a liquid, a powder, or a combinationthereof.
 4. The system of claim 1 wherein the historical databasecomprises a trend of TDS concentration to ion concentration.
 5. Thesystem of claim 1 wherein the step of selecting at least one frictionreducing polymer comprises using a historical database and correlatingthe ion concentration to friction reducing polymers that reduce frictionat the ion concentration.
 6. The system of claim 5 wherein the frictionreducing polymer selected will not lose more than 15% friction reductionability for a period of 15 minutes at the ion concentration.
 7. A systemcomprising: a historical database comprising a total dissolved solids(TDS) concentration, density, and an ion concentration of a plurality ofwater sources over time; a fracturing blender fluidically coupled to awellbore; a water testing equipment disposed between a source of waterand the fracturing blender wherein the water testing equipment isoperable to measure at least one property of the source of water; and acontrol system comprising: at least one processor; and a memory coupledto the processor to provide software that configures the processor to:receive an input signal from the water testing equipment, access thehistorical database, correlate the at least one property of the sourceof water to a TDS concentration of the source of water; reference thehistorical database to correlate the TDS concentration of the pluralityof the source of water to the ion concentration of the source of water;select a friction reducing polymer based at least in part on the ionconcentration of the source of water, and send an output signal to thefracturing blender to add the friction reducing polymer to thefracturing blender.
 8. The system of claim 7, the water testingequipment comprises equipment capable of measuring a property selectedfrom conductivity, reflected radiation, emitted radiation, or acombination thereof of the source of water.
 9. The system of system 7,wherein the historical database comprises a trend of TDS concentrationto ion concentration.
 10. The system of claim 7, wherein the ionconcentration is a concentration of at least one Group(I) ion, at leastone Group(II) ion, at least one metal ion, or a combination thereof. 11.The system of claim 7, wherein the processor is configured to select thefriction reducing polymer using the historical database and correlatingthe ion concentration to friction reducing polymers that reduce frictionat the ion concentration.
 12. The system of claim 7, wherein thefracturing lender is further configured to add the selected frictionreducing polymer to a hydraulic fracturing fluid comprising the sourceof water.
 13. The system of claim 7, wherein the water testing equipmentis configured to measure a conductivity of the source of water, whereinthe conductivity is used to determine the TDS concentration.
 14. Thesystem of claim 7, wherein the selecting at least one friction reducingpolymer is automatic.
 15. The system of claim 7, wherein processor isfurther configured to accept a user input to manually select thefriction reducing polymer.
 16. A system comprising: a historicaldatabase comprising a total dissolved solids (TDS) concentration,density, and an ion concentration of a plurality of water sources overtime; a fracturing blender fluidically coupled to a wellbore; a watertesting equipment disposed between a source of water and the fracturingblender wherein the water testing equipment is configured to measure adensity of the source of water; and a control system comprising: atleast one processor; and a memory coupled to the processor to providesoftware that configures the processor to: receive an input signal fromthe water testing equipment, the input signal comprising the density ofthe source of water, access the historical database, correlate thedensity of the source of water to a TDS concentration of the source ofwater; reference the historical database to correlate the TDSconcentration of the plurality of the source of water to the ionconcentration of the source of water; select a friction reducing polymerbased at least in part on the ion concentration of the source of water,and send an output signal to the fracturing blender to add the frictionreducing polymer to the fracturing blender.
 17. The system of system 16,wherein the historical database comprises a trend of TDS concentrationto ion concentration.
 18. The system of claim 16, wherein the processoris configured to select the friction reducing polymer using thehistorical database and correlating the ion concentration to frictionreducing polymers that reduce friction at the ion concentration
 19. Thesystem of claim 16, wherein the fracturing lender is further configuredto add the selected friction reducing polymer to a hydraulic fracturingfluid comprising the source of water.
 20. The system of claim 16,wherein the selecting at least one friction reducing polymer isautomatic